1. Field of the Invention
The invention relates generally to compositional characterization and quantification of solid deposits from hydrocarbon fluids.
2. Description of Related Art
When fluids are transported by flowing through pipes or tubing, the deposition of solids from the fluid onto the interior walls of the pipes or tubing may impair fluid flow. An example of such fluids is crude oil. Some solids may be pre-existing in the fluids, and some solids may form during storage or transport due to environmental changes that lead to phase transition. Crude oils from many formations commonly contain solids, often as one or more of waxes (paraffin waxes), asphaltenes, sulfur, scale, and hydrates. Paraffin waxes are essentially mixtures of long-chain n-paraffins with carbon chain lengths ranging from C15 to C90+.
Asphaltenes and residual oil components often co-precipitate with the paraffin waxes and result in varying appearance (color) and texture of the precipitated solids. Asphaltenes are generally compounds including more than about 70 carbon atoms, which are mostly aromatic polycyclic compounds variably substituted with alkyl groups. Asphaltenes may also contain heteroatoms (such as nitrogen, sulfur, or oxygen), metals (such as nickel, vanadium, or iron), or both. Hydrates generally include water molecules in an ice-like structure encaging one or more organic compounds. The organic compounds encaged by the ice-like structure are commonly methane, ethane, propane, or other alkanes with less than about 10 carbon atoms.
Under many conditions, the compounds that are capable of forming solids in a fluid may remain dissolved in the fluid. However, when a fluid, such as crude oil, is transported via pipe, such as from a geologic formation to a wellhead via production tubing or from a wellhead or a storage vessel to a refinery via a pipeline, changes in the pressure, temperature, composition, or other parameters of the flowing fluid may lead to precipitation and deposition of solids. Deposition in a pipe is generally undesirable, because deposited solids would at least partially block the pipe, leading to reductions in the flow rates of fluids in the pipe. When this occurs, expensive and time-consuming cleaning of the pipe is required to restore the maximum flow rates of the fluids.
Similar problems can also arise for other fluids which may contain solids. Such fluids, either liquids or gases, include fluids used in the industrial production of paint, food products, pharmaceuticals, plastics, and paper and paper products, among other industries.
Currently, a visual pressure-volume-temperature (PVT) cell equipped with fiber optic light transmission probes (source and detector) is typically used to detect the onset of organic solids precipitation (due to temperature, pressure and/or compositional changes) concurrently with fluid volumetric measurements. These fiber optic probes are mounted across the windows of the visual PVT cell. The visual PVT cell together with the optical probes and the computerized pump are referred to as a Solids Detection System (SDS). The measurement principle of the SDS is based on transmittance of a laser light through the test fluid white temperature, pressure, or the fluid composition is being changed.
The entire system is typically controlled by a software package that accomplishes two significant objectives. First, a computerized pump is used to control and maintain the system pressure during isobaric temperature sweeps for wax precipitation experiments. Second, the software (in real time) records and displays the system temperature, pressure, solvent volume, time, and, most importantly, the power of transmitted light (PTL) through the test fluid.
The standard SDS configuration discussed above may be further improved with the addition of high-pressure microscopy (HPM) in series. The HPM cell is a small sapphire prototype with variable internal diameters (and hence working volumes) It is typically connected to the bottom of a PVT cell inside the same air-bath oven.
Another common method for measuring wax appearance temperature and wax disappearance temperature uses cross polar microscopy (CPM). CPM is based on the fact that most crystalline materials rotate the plane of polarization of transmitted polarized light. By crossing two prisms on opposite sides of the oil sample, all light is initially blocked and the entire field of view appears black. On cooling, the crystallizing material appears as bright spots against this black background. This technique usually provides a conservative (or highest) value of the crude oil cloud point temperature due to CPM's ability to detect small crystals, i.e. during early stages of wax crystallization.
While such prior art methods, such as SDS and CPM, have been found to be useful, their sensitivities may not be sufficient for some applications. With these prior art methods, only particles larger than 2 microns are typically detected. This limitation results in a delay in the measurements of wax formation. As a result, there is often a discrepancy between the wax appearance temperature and the wax disappearance temperature. Consequently, there still exists a need for better methods for wax appearance temperature measurements.